1. Field of the Invention
The present invention generally relates to methods and apparatus for use in oil and gas wellbores. More particularly, the invention relates to using instrumentation to monitor downhole conditions within wellbores. More particularly, the invention relates to methods and apparatus for controlling the use of valves and other automated downhole tools through the use of instrumentation that can additionally be used as a relay to the surface. More particularly still, the invention relates to the use of deployment valves in wellbores in order to temporarily isolate an upper portion of the wellbore from a lower portion thereof.
2. Description of the Related Art
Oil and gas wells typically begin by drilling a borehole in the earth to some predetermined depth adjacent a hydrocarbon-bearing formation. After the borehole is drilled to a certain depth, steel tubing or casing is typically inserted in the borehole to form a wellbore and an annular area between the tubing and the earth is filled with cement. The tubing strengthens the borehole and the cement helps to isolate areas of the wellbore during hydrocarbon production.
Historically, wells are drilled in an “overbalanced” condition wherein the wellbore is filled with fluid or mud in order to prevent the inflow of hydrocarbons until the well is completed. The overbalanced condition prevents blow outs and keeps the well controlled. While drilling with weighted fluid provides a safe way to operate, there are disadvantages, like the expense of the mud and the damage to formations if the column of mud becomes so heavy that the mud enters the formations adjacent the wellbore. In order to avoid these problems and to encourage the inflow of hydrocarbons into the wellbore, underbalanced or near underbalanced drilling has become popular in certain instances. Underbalanced drilling involves the formation of a wellbore in a state wherein any wellbore fluid provides a pressure lower than the natural pressure of formation fluids. In these instances, the fluid is typically a gas, like nitrogen and its purpose is limited to carrying out drilling chips produced by a rotating drill bit. Since underbalanced well conditions can cause a blow out, they must be drilled through some type of pressure device like a rotating drilling head at the surface of the well to permit a tubular drill string to be rotated and lowered therethrough while retaining a pressure seal around the drill string. Even in overbalanced wells there is a need to prevent blow outs. In most every instance, wells are drilled through blow out preventers in case of a pressure surge.
As the formation and completion of an underbalanced or near underbalanced well continues, it is often necessary to insert a string of tools into the wellbore that cannot be inserted through a rotating drilling head or blow out preventer due to their shape and relatively large outer diameter. In these instances, a lubricator that consists of a tubular housing tall enough to hold the string of tools is installed in a vertical orientation at the top of a wellhead to provide a pressurizable temporary housing that avoids downhole pressures. By manipulating valves at the upper and lower end of the lubricator, the string of tools can be lowered into a live well while keeping the pressure within the well localized. Even a well in an overbalanced condition can benefit from the use of a lubricator when the string of tools will not fit though a blow out preventer. The use of lubricators is well known in the art and the forgoing method is more fully explained in U.S. patent application Ser. No. 09/536,937, filed 27 Mar. 2000, and that published application is incorporated by reference herein in its entirety.
While lubricators are effective in controlling pressure, some strings of tools are too long for use with a lubricator. For example, the vertical distance from a rig floor to the rig draw works is typically about ninety feet or is limited to that length of tubular string that is typically inserted into the well. If a string of tools is longer than ninety feet, there is not room between the rig floor and the draw works to accommodate a lubricator. In these instances, a down hole deployment valve or DDV can be used to create a pressurized housing for the string of tools. Downhole deployment valves are well known in the art and one such valve is described in U.S. Pat. No. 6,209,663, which is incorporated by reference herein in its entirety. Basically, a DDV is run into a well as part of a string of casing. The valve is initially in an open position with a flapper member in a position whereby the full bore of the casing is open to the flow of fluid and the passage of tubular strings and tools into and out of the wellbore. In the valve taught in the '663 patent, the valve includes an axially moveable sleeve that interferes with and retains the flapper in the open position. Additionally, a series of slots and pins permits the valve to be openable or closable with pressure but to then remain in that position without pressure continuously applied thereto. A control line runs from the DDV to the surface of the well and is typically hydraulically controlled. With the application of fluid pressure through the control line, the DDV can be made to close so that its flapper seats in a circular seat formed in the bore of the casing and blocks the flow of fluid through the casing. In this manner, a portion of the casing above the DDV is isolated from a lower portion of the casing below the DDV.
The DDV is used to install a string of tools in a wellbore as follows: When an operator wants to install the tool string, the DDV is closed via the control line by using hydraulic pressure to close the mechanical valve. Thereafter, with an upper portion of the wellbore isolated, a pressure in the upper portion is bled off to bring the pressure in the upper portion to a level approximately equal to one atmosphere. With the upper portion depressurized, the wellhead can be opened and the string of tools run into the upper portion from a surface of the well, typically on a string of tubulars. A rotating drilling head or other stripper like device is then sealed around the tubular string or movement through a blowout preventer can be re-established. In order to reopen the DDV, the upper portion of the wellbore must be repressurized in order to permit the downwardly opening flapper member to operate against the pressure therebelow. After the upper portion is pressurized to a predetermined level, the flapper can be opened and locked in place. Now the tool string is located in the pressurized wellbore.
Presently there is no instrumentation to know a pressure differential across the flapper when it is in the closed position. This information is vital for opening the flapper without applying excessive force. A rough estimate of pressure differential is obtained by calculating fluid pressure below the flapper from wellhead pressure and hydrostatic head of fluid above the flapper. Similarly when the hydraulic pressure is applied to the mandrel to move it one way or the other, there is no way to know the position of the mandrel at any time during that operation. Only when the mandrel reaches dead stop, its position is determined by rough measurement of the fluid emanating from the return line. This also indicates that the flapper is either fully opened or fully closed. The invention described here is intended to take out the uncertainty associated with the above measurements.
In addition to monitoring the pressure differential across the flapper and the position of the flapper in a DDV, it is sometimes desirable to monitor well conditions in situ. Recently, technology has enabled well operators to monitor conditions within a wellbore by installing monitoring systems downhole. The monitoring systems permit the operator to monitor multiphase fluid flow, as well as pressure, seismic conditions, vibration of downhole components, and temperature during production of hydrocarbon fluids. Downhole measurements of pressure, temperature, seismic conditions, vibration of downhole components, and fluid flow play an important role in managing oil and gas or other sub-surface reservoirs.
Historically, monitoring systems have used electronic components to provide pressure, temperature, flow rate, water fraction, and other formation and wellbore parameters on a real-time basis during production operations. These monitoring systems employ temperature gauges, pressure gauges, acoustic sensors, seismic sensors, electromagnetic sensors, and other instruments or “sondes”, including those which provide nuclear measurements, disposed within the wellbore. Such instruments are either battery operated, or are powered by electrical cables deployed from the surface. The monitoring systems have historically been configured to provide an electrical line that allows the measuring instruments, or sensors, to send measurements to the surface.
Recently, optical sensors have been developed which communicate readings from the wellbore to optical signal processing equipment located at the surface. Optical sensors have been suggested for use to detect seismic information in real time below the surface after the well has been drilled for processing into usable information. Optical sensors may be disposed along tubing strings such as production tubing inserted into an inner diameter of a casing string within a drilled-out wellbore by use of inserting production tubing with optical sensors located thereon. The production tubing is inserted through the inner diameter of the casing strings already disposed within the wellbore after the drilling operation. In either instance, an optical line or cable is run from the surface to the optical sensor downhole. The optical sensor may be a pressure gauge, temperature gauge, acoustic sensor, seismic sensor, or other sonde. The optical line transmits optical signals to the optical signal processor at the surface.
The optical signal processing equipment includes an excitation light source. Excitation light may be provided by a broadband light source, such as a light emitting diode (LED) located within the optical signal processing equipment. The optical signal processing equipment also includes appropriate equipment for delivery of signal light to the sensor(s), e.g., Bragg gratings or lasers and couplers which split the signal light into more than one leg to deliver to more than one sensor. Additionally, the optical signal processing equipment includes appropriate optical signal analysis equipment for analyzing the return signals from the Bragg gratings.
The optical line is typically designed so as to deliver pulses or continuous signals of optic energy from the light source to the optical sensor(s). The optical cable is also often designed to withstand the high temperatures and pressures prevailing within a hydrocarbon wellbore. Preferably, the optical cable includes an internal optical fiber which is protected from mechanical and environmental damage by a surrounding capillary tube. The capillary tube is made of a high strength, rigid-walled, corrosion-resistant material, such as stainless steel. The tube is attached to the sensor by appropriate means, such as threads, a weld, or other suitable method. The optical fiber contains a light guiding core which guides light along the fiber. The core preferably employs one or more Bragg gratings to act as a resonant cavity and to also interact with the sonde.
Optical sensors, in addition to monitoring conditions within a drilled-out well or a portion of a well during production operations, may also be used to acquire seismic information from within a formation prior to drilling a well. Initial seismic data is generally acquired by performing a seismic survey. A seismic survey maps the earth formation in the subsurface of the earth by sending sound energy or acoustic waves down into the formation from a seismic source and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come from explosions, seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is moved to multiple preplanned locations on the surface of the earth above the geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple energy activation/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2-D) seismic survey, the recording locations are generally laid out along a single straight line, whereas in a three-dimensional (3-D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2-D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3-D survey produces a data “cube” or volume that is, at least conceptually, a 3-D picture of the subsurface that lies beneath the survey area. A 4-D survey produces a 3-D picture of the subsurface with respect to time, where time is the fourth dimension.
After the survey is acquired, the data from the survey is processed to remove noise or other undesired information. During the computer processing of seismic data, estimates of subsurface velocity are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock properties (including permeability and elastic parameters), water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
The procedure for seismic monitoring with optical sensors after the well has been drilled is the same as above-described in relation to obtaining the initial seismic survey, except that more locations are available for locating the seismic source and seismic sensor, and the optical information must be transmitted to the surface for processing. To monitor seismic conditions within the formation, a seismic source transmits a signal into the formation, then the signal reflects from the formation to the seismic sensor. The seismic source may be located at the surface of the wellbore, in an adjacent wellbore, or within the well. The seismic sensor then transmits the optical information regarding seismic conditions through an optical cable to the surface for processing by a central processing unit or some other signal processing device. The processing occurs as described above in relation to the initial seismic survey. In addition to the seismic source reflecting from the formation to the seismic sensor, a signal may be transmitted directly from the seismic source to the seismic sensor.
Seismic sensors must detect seismic conditions within the formation to some level of accuracy to maintain usefulness; therefore, seismic sensors located on production tubing have ordinarily been placed in firm contact with the inside of casing strings to couple the seismic sensor to the formation, thereby reducing fluid attenuation or distortion of the signal and increasing accuracy of the readings. Coupling the seismic sensor to the formation from production tubing includes distance and therefore requires complicated maneuvers and equipment to accomplish the task.
Although placing the seismic sensor in direct contact with the inside of the casing string allows more accurate readings than current alternatives because of its coupling to the formation, it is desirable to even further increase the accuracy of the seismic readings by placing the seismic sensor closer to the formation from which it is obtaining measurement. The closer the seismic sensor is to the formation, the more accurate the signal obtained. A vibration sensor for example, such as an accelerometer or geophone, must be placed in direct contact with the formation to obtain accurate readings. It is further desirable to decrease the complication of the maneuvers and equipment required to couple the seismic sensor to the formation. Therefore, it is desirable to place the seismic sensor as close to the formation as possible.
While current methods of measuring wellbore and formation parameters using optical sensors allow for temporary measurement of the parameters before the drilling and completion operations of the wellbore at the surface and during production operations on production tubing or other production equipment, there is a need to permanently monitor wellbore and formation conditions and parameters during all wellbore operations, including during the drilling and completion operations of the wellbore. It is thus desirable to obtain accurate real time readings of seismic conditions while drilling into the formation. It is further desirable to permanently monitor downhole conditions before and after production tubing is inserted into the wellbore.
In addition to problems associated with the operation of DDVs, many prior art downhole measurement systems lack reliable data communication to and from control units located on the surface. For example, conventional measurement while drilling (MWD) tools utilize mud pulse, which works fine with incompressible drilling fluids such as a water-based or an oil-based mud, but they do not work when gasified fluids or gases are used in underbalanced drilling. An alternative to this is electromagnetic (EM) telemetry where communication between the MWD tool and the surface monitoring device is established via electromagnetic waves traveling through the formations surrounding the well. However, EM telemetry suffers from signal attenuation as it travels through layers of different types of formations. Any formation that produces more than minimal loss serves as an EM barrier. In particular salt domes tend to completely attenuate or moderate the signal. Some of the techniques employed to alleviate this problem include running an electric wire inside the drill string from the EM tool up to a predetermined depth from where the signal can come to the surface via EM waves and placing multiple receivers and transmitters in the drill string to provide boost to the signal at frequent intervals. However, both of these techniques have their own problems and complexities. Currently, there is no available means to cost efficiently relay signals from a point within the well to the surface through a traditional control line.
Expandable Sand Screens (ESS) consist of a slotted steel tube, around which overlapping layers of filter membrane are attached. The membranes are protected with a pre-slotted steel shroud forming the outer wall. When deployed in the well, ESS looks like a three-layered pipe. Once it is situated in the well, it is expanded with a special tool to come in contact with the wellbore wall. The expander tool includes a body having at least two radially extending members, each of which has a roller that when coming into contact with an inner wall of the ESS, can expand the wall past its elastic limit. The expander tool operates with pressurized fluid delivered in a string of tubulars and is more completely disclosed in U.S. Pat. No. 6,425,444 and that patent is incorporated in its entirety herein by reference. In this manner ESS supports the wall against collapsing into the well, provides a large wellbore size for greater productivity, and allows free flow of hydrocarbons into the well while filtering out sand. The expansion tool contains rollers supported on pressure-actuated pistons. Fluid pressure in the tool determines how far the ESS is expanded. While too much expansion is bad for both the ESS and the well, too little expansion does not provide support to the wellbore wall. Therefore, monitoring and controlling fluid pressure in the expansion tool is very important. Presently fluid pressure is measured with a memory gage, which of course provides information after the job has been completed. A real time measurement is desirable so that fluid pressure can be adjusted during the operation of the tool if necessary.
There is a need therefore, for a downhole system of instrumentation and monitoring that can facilitate the operation of downhole tools. There is a further need for a system of instrumentation that can facilitate the operation of downhole deployment valves. There is yet a further need for downhole instrumentation apparatus and methods that include sensors to measure downhole conditions like pressure, temperature, seismic conditions, flow rate, differential pressure, distributed temperature, and proximity in order to facilitate the efficient operation of the downhole tools. There exists a further need for downhole instrumentation and circuitry to improve communication with existing expansion tools used with expandable sand screens and downhole measurement devices such as MWD and pressure while drilling (PWD) tools. There is a need for downhole instrumentation which requires less equipment to couple to the formation to obtain accurate readings of wellbore and formation parameters. Finally, there exists a need for the ability to measure with substantial accuracy downhole wellbore and formation conditions during drilling into the formation, as well as a need for the ability to subsequently measure downhole conditions after the wellbore is drilled by permanent monitoring.